1. Field of the Invention
The present invention relates to optimization of the development of underground reservoirs such as hydrocarbon reservoirs, notably those comprising a network of fractures.
2. Description of the Prior Art
The petroleum industry, and more precisely petroleum reservoir exploration and development, requires knowledge of the underground geology as perfectly as possible to efficiently provide evaluation of reserves, production modelling or development management. In fact, determining the location of a production well or of an injection well, the drilling mud composition, the completion characteristics, the parameters required for optimum hydrocarbon recovery (such as injection pressure, production flow rate, etc.) requires good knowledge of the reservoir. Reservoir knowledge notably means knowledge of the petrophysical properties of the subsoil at any point in space.
The petroleum industry has therefore combined for a long time field (in-situ) measurements with experimental modelling (performed in the laboratory) and/or numerical modelling (using softwares). Petroleum reservoir modelling thus is a technical stage that is essential for any reservoir exploration or development procedure. The goal of modelling is to provide a description of the reservoir.
Fractured reservoirs are an extreme type of heterogeneous reservoirs comprising two very different media, a matrix medium containing the major part of the oil in place and having a low permeability, and a fractured medium representing less than 1% of the oil in place and highly conductive. The fractured medium itself can be complex, with different sets of fractures characterized by their respective density, length, orientation, inclination and opening.
Engineers in charge of the development of fractured reservoirs need to know as perfectly as possible the role of fractures. What is referred to as fracture is a plane discontinuity of very small thickness in relation to the extent thereof, representing a fracture plane of rock of the reservoir.
On the one hand, knowledge of the distribution and of the behavior of fractures allows optimization of the location and the spacing between wells to be drilled through the oil-bearing reservoir.
On the other hand, the geometry of the fracture network conditions and the fluid displacement at the reservoir scale as well as the local scale where it determines elementary matrix blocks in which the oil is trapped. Knowing the distribution of the fractures is therefore also very helpful, at a later stage, to reservoir engineers who want to calibrate the models which are constructed to simulate the reservoirs in order to reproduce or to predict the past or future production curves.
Geoscience specialists therefore have three-dimensional images of reservoirs allowing location of a large number of fractures.
However, in order to predict fluid flows which are likely to occur through the reservoir and thus to simulate the production of hydrocarbons according to various production scenarios, software is used which referred to as a “flow simulator” which allows carrying out reservoir simulations, that is simulations of flow within the reservoir. Flow simulators are based on numerical schemes that do not allow three-dimensional images of fracture networks to be directly used. The representation of a fracture network in flow simulators has long been considered as unrealistic because the network configuration is partly unknown, and because of the numerical limitations linked with the juxtaposition of many cells having very different dimensions and properties.
Simplified but realistic modelling of such media therefore is of great relevance to reservoir specialists.
There is a well-known approach, referred to as the “double porosity approach”, as described for example by Warren J. E. et al. in “The Behavior of Naturally Fractured Reservoirs”, SPE Journal (September 1963), 245-255. This technique allows interpretation of the double porosity (or double medium) behavior of a fractured reservoir from a single-phase flow well test. According to this approach, any elementary volume (cell) of the fractured reservoir is modelled in a form of a set of identical parallelepipedic blocks referred to as equivalent blocks. These blocks are limited by an orthogonal system of continuous uniform fractures oriented along the main directions of flow. The flow of the fluids, at the reservoir scale, occurs through the fractures only, and fluid exchanges take place locally between the fractures and the matrix blocks.
It is however necessary to calculate the dimensions of the equivalent parallelepipedic blocks. Finally, French Patent 2,757,957 and counterpart U.S. Pat. No. 6,064,944, describe a method for determining the equivalent block dimensions. This method allows defining a single equivalent block of rectangular section for each layer of the reservoir. Now, the geological reality is often complex, to such an extent that the representation of the fractures by a single equivalent block is often too imprecise to allow the matrix/fracture exchanges to be estimated with sufficient precision.